Method for Determining A Filtration Velocity of Reservoir Fluids

ABSTRACT

Temperature is measured in a shut-in wellbore and rates of temperature change in depth intervals within productive layers and in depth intervals adjacent to the productive layers are determined. Areas are selected in the depth intervals within the productive layers wherein the rate of temperature change is significantly higher than the rate of change in the depth intervals adjacent to the productive layers. A numerical model of temperature change in the shut-in wellbore is created taking into account a filtration effect of a reservoir fluid on the rate of the temperature change in the shut-in wellbore. The measurement results are compared with the numerical modeling results, and their best match is used for determining a fluid filtration velocity in the selected areas in the depth intervals within the productive layers.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to Russian Application No. 2013146561 filed Oct. 18, 2013, which is incorporated herein by reference in its entirety.

TECHNICAL FIELD

This invention relates to geophysical well logging and is intended for determination of reservoir fluid velocities in oil wells.

BACKGROUND

The optimization of the pattern and behavior of producing and injecting wells requires information on directions and flow rates of reservoir fluids in oil reservoirs with dozens or hundreds of wells drilled. This information allows specifying the hydrodynamic model of an oil reservoir. Reservoir fluid flow information is particularly important for high-viscosity oil production. Besides the heterogeneity of oil reservoir properties, which can be obtained from geophysical studies, the production process is characterized by heterogeneity of reservoir filtration properties associated with reservoir fluid composition. Water-filled (low viscosity) channels may occur between injection and producing wells, through which the injected water enters the producing wells providing no oil displacement and no heating of oil-containing areas of the reservoir. In this respect, development of methods for controlling reservoir fluid flows in oil reservoirs with a great number of production and injection wells is of great interest.

At present, reservoir fluid flows in oil reservoirs are controlled indirectly by monitoring hydraulic relation between wells through an interference test. See, for example, Amanat U. Chaudhry, Oil Well Testing Handbook, Elsevier Science, 2004, p. 429-462. This method is based on observing pressure change in non-operating wells when the behavior of active wells is changed.

A more direct method consists in tracing filtration flows with tracer materials. See, for example, G. Michael Shook, Shannon L. Ansley, Allan Wylie, Tracers and Tracer Testing: Design, Implementation, and Interpretation Methods, 2004, INEEL. The method involves adding a tracer into a fluid injected into a well and registering a moment of appearance of the tracer and its concentration in a fluid flowing out of producing wells. Various chemical and radioactive substances are used as tracers. They should be water-soluble, have no precipitation, no rock sorbing, be registrable within a wide range of concentrations, etc. Filtration flow tracing is quite an expensive and laborious method not very often used. Besides, tracing allows estimating only an average fluid filtration velocity between an injection well and a production well. The fluid filtration velocity at the producing well location (as if it was shut down) remains unknown.

SUMMARY

The disclosure provides a method for identifying depth intervals (layers), where the fluid flow occurs, and estimating their filtration velocity at the observation well location.

The method comprises measuring temperature in a shut-in wellbore and determining a rate of temperature change in depth intervals within productive layers and a rate of temperature change in depth intervals adjacent to the productive layers. Areas are selected in the depth intervals within the productive layers wherein the rate of temperature change is significantly higher than the rate of change in the depth intervals adjacent to the productive layers. A numerical model of temperature change in the shut-in wellbore is created taking into account a filtration effect of a reservoir fluid on the rate of the temperature change in the shut-in wellbore. The measurement results are compared with the numerical modeling results, and their best match is used for determining a fluid filtration velocity in the selected areas in the depth intervals within the productive layers.

According to one of the embodiments of the disclosure, the temperature in the shut-in well is measured with a fiber-optic gauge.

According to another embodiment of the disclosure, the temperature in the shut-in well is measured by means of at least three temperature loggings of the well.

The temperature measurements are performed in the shut-in well upon completing cementation, production, fluid injection, or circulation.

The areas wherein the rate of temperature change is significantly higher than the rate of change in the depth intervals adjacent to the productive layers could be selected after 10 to 30 hours of the wellbore shut-in.

BRIEF DESCRIPTION OF DRAWINGS

Those skilled in the art should more fully appreciate advantages of various embodiments of the present disclosure from the following drawings:

FIG. 1 shows examples of disturbing a reservoir thermal field prior to temperature measurements in a shut-in well;

FIG. 2 shows a simulated temperature in the reservoir at the end of 30 days production;

FIG. 3 shows a simulated temperature field in the reservoir at the end of 3 days of shut-in;

FIG. 4 shows simulated well temperatures normalized to an initial deviation of the well temperature from the reservoir temperature;

FIG. 5 shows normalized temperature change rates for two filtration velocities;

FIG. 6 shows a relation between the normalized temperature change rate to the filtration velocity at shut-in time 20 hours; and

FIG. 7 shows a chart of the estimation domain used for estimation of the filtration velocity using numerical modeling.

DETAILED DESCRIPTION

The suggested method is based on a dependence of the rate of temperature change, measured in an observation well, on the presence and velocity of fluid filtration in a reservoir intersected by a wellbore.

This method is implemented in the following way. A temperature profile is measured with temperature logging devices or a fiber temperature gauge along a shut-in wellbore after cementing (FIG. 1 a), production (FIG. 1 b), fluid injection (FIG. 1 c), or circulation (FIG. 1 d). In case of logging, at least 3-5 temperature measurements are performed. In many cases, an initial temperature in the wellbore and in a near-wellbore zone differs from temperature of the rocks distant (a few meters) from the wellbore.

The rate of temperature change measured in the wellbore at various depths is calculated in depth intervals within productive layers, in depth intervals adjacent to the productive layers, and in those adjoining the reservoirs (at a distance of not more than a few dozen meters).

After a shut-in time 10-30 hours, areas are selected in the depth intervals within the productive layers wherein the rate of temperature change is significantly higher than the rate of change in depth intervals adjacent to the productive layers.

A numerical model of temperature change in the shut-in wellbore is created taking into account an influence of the reservoir fluid filtration on the temperature change rate in the shut-in well. The measurement results are compared with the numerical modeling results, and the best match of the measurement and modeling results is used for determining a fluid filtration velocity in the selected areas in the depth intervals within the productive layers.

The possibility of selecting depth intervals and estimating the reservoir fluid filtration velocity was demonstrated on synthetic cases generated by commercial simulator COMSOL Multiphysics 3.5®.

2D modeling of a stationary field of pressure (and filtration velocity) and of a nonstationary field of temperatures was performed in a horizontal homogeneous estimation domain including the wellbore.

The pressure and temperature equations are:

Δ P = 0 ${{{\delta \cdot \rho_{f}}{c_{f} \cdot \frac{\partial T}{\partial t}}} + {\bigtriangledown \left( {{{- \lambda} \cdot \bigtriangledown}\; T} \right)}} = {{- \rho_{f}}{c_{f} \cdot V \cdot \bigtriangledown}\; T\mspace{14mu} {where}}$ $\overset{\_}{V} = {- {\frac{k}{\mu}.}}$

∇P is a fluid filtration velocity,

${\delta = {\varphi + {\left( {1 - \varphi} \right) \cdot \frac{\rho_{m}c_{m}}{\rho_{f}c_{f}}}}},$

k is reservoir permeability, μ is viscosity of a filtered fluid, λ is thermal conductivity of the fluid-saturated reservoir, ρ_(m)c_(m) is bulk thermal capacity of reservoir crystal matrix, ρ_(f)c_(f) is fluid bulk thermal capacity, and φ is reservoir porosity.

Equation boundary conditions for the pressure calculations include (FIG. 7) (i) impermeable upper and lower boundaries of the estimation domain the wellbore surface and (ii) specified pressures P₁ and P₂ on a left boundary and on a right boundary of the estimation domain. The pressure difference of P₁−P₂ was selected in a way to provide the required fluid filtration velocity at the specified reservoir permeability.

Boundary conditions for the energy equation (FIG. 7) include (i) heat-insulated upper and lower boundaries of the estimation domain, (ii) temperature T₀ (equal to the reservoir temperature) on the left boundary, and (iii) the free outflow condition on the right boundary of the estimation domain.

The calculation was performed in two stages.

At a first stage, a constant temperature was specified for wellbore boundaries, the temperature corresponds to the temperature of the fluid flowing in the wellbore during production or circulation. A temperature field at the end of circulation was calculated and used as an initial condition for a second stage. At the second stage, temperature field evolution after the wellbore shut-in was calculated. The calculation covered the entire estimation domain including the wellbore.

As an example, let us consider a reservoir with two productive layers, producing from a lower layer (FIG. b). FIG. 2 shows a simulated temperature field in an upper layer (at a fixed depth) after 30 day production at the filtration velocity in this layer of 0.25 m/day.

The simulated temperature field in the layer after 3 days shut-in is shown in FIG. 3. The wellbore is shown with a black circle. Since a size of an area where the temperature substantially differs from the reservoir temperature exceeds the wellbore radius notably, the area of the fluid with a higher temperature moves with the filtered fluid. As a result, the temperature measured in the wellbore changes faster than with no flow.

The simulated temperatures in the wellbore normalized to an initial deviation of the wellbore temperature from the reservoir temperature at the filtration velocities of 0.12 and 0.25 m/day are shown in FIG. 4 (curve 1—V=0, curve 2—V=0.12 m/day, and curve 3—V=0.25 m/day). FIG. 5 shows the temperature change rate at the filtration velocities of 0.12 and 0.25 m/day normalized to the temperature change rate with no filtration in the reservoir (curve 1—V=0.25 m/day and curve 2—V=0.12 m/day).

According to the calculations, a temperature relaxation rate normalized in this way is highest within the time interval of 10-30 hours after wellbore shut-in. FIG. 6 shows the relation of this value to the fluid filtration velocity at 20 hours shut-in. The specific expression of the normalized temperature relaxation rate depends on wellbore configuration and rock thermal properties, and should be calculated in each particular case (e.g., using the commercial simulator COMSOL Multiphysics 3.5®). According to FIG. 6, the suggested method allows obtaining information on filtration flows having velocity of more than 0.03-0.95 m/day. 

1. A method for determining a reservoir fluid filtration velocity, comprising: measuring temperature in a shut-in wellbore; determining a rate of temperature change at depth intervals within productive layers and a rate of temperature change at depth intervals adjacent to the productive layers; selecting areas at the depth intervals within the productive layers wherein the rate of temperature change is significantly higher than the rate of change at depth intervals adjacent to the productive layers; creating a numerical model of temperature change in the shut-in wellbore taking into account a filtration effect of a reservoir fluid on the rate of the temperature change in the shut-in wellbore; comparing the measurement results with the numerical modeling results; and determining the filtration velocity of the reservoir fluids in the selected areas at the depth intervals within the productive layers by matching the measurement results with the numerical simulation results.
 2. The method of claim 1, wherein the temperature in the shut-in well is measured with a fiber-optic gauge.
 3. The method of claim 1, wherein the temperature in the shut-in well is measured by means of at least three temperature loggings of the well.
 4. The method of claim 1, wherein the areas where the rate of temperature change is significantly higher than the rate of change in the depth intervals adjacent to the productive layers are selected after 10 to 30 hours of the wellbore shut-in.
 5. The method of claim 1, wherein the temperature measurements in the shut-in wellbore are performed after cementation.
 6. The method of claim 1, wherein the temperature measurements in the shut-in wellbore are performed after production.
 7. The method of claim 1, wherein the temperature measurements in the shut-in wellbore are performed after fluid injection.
 8. The method of claim 1, wherein the temperature measurements in the shut-in wellbore are performed after fluid circulation. 